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 SOUTH DAKOTA GAS RATE SCHEDULE NORTHWESTERN ENERGY PUBLIC SERVICE CORPORATION d/b/a NORTHWESTERN ENERGY SIOUX FALLS SectionNo.3 SOUTHDAKOTA 454thRevised SheetNo.9a Canceling 453rdRevised SheetNo.9a ADJUSTMENTCLAUSERATES PerTherm Delivered Cost of Energy Per Month Rate No. 81 - Residential Gas Service Gas Commodity Charge $0.58811 Rate No. 82 - General Gas Service Gas Commodity Charge $0.58811 Rate No. 84 - Commercial and Industrial-Firm GasDemand Charge, per therm of daily contract demand (never less than 50 therms) NNG Pipeline Capacity Costs N N G R a t e / T h e r m 36.85%ofTF12Base $1.2933 $0.45 25.46%ofTF12Variable $1.5481 0.39 37.69%ofTF5 $2.7599 0.41 GRI Fee $0.0000 0.00 SBA Surcharge $0.0000 0.00 GSR Surcharge $0.0000 0.00 Order528Surcharge $0.0000 0.00 Stranded 858 Surcharge $0.0000 0.00 Total Pipeline Capacity Costs $ 1.25 NNG R e fund - 0 . 1 8 S u p p ly Standby 0.07 B a lancing Services 0.09 Total D e mand Charge $ 1 . 2 3 Theabovepercentages are, based on the Company’s contract demand profile with NNG ( 4 9 , 0 2 0 MMBtu.), Rate Schedule MMBtu Demand Percentage T F 1 2 Base 18,063 3 6 . 8 5 % T F 1 2 V a r iable 1 2 , 4 8 3 2 5 . 4 6 % T F 5 1 8 , 4 7 4 ( 1 ) 3 7 . 6 9 % T o tals 4 9 , 0 2 0 1 0 0 . 0 0 % (1)Service is contracted for 5 months (15.70% is 5/12ths of 37.69%) G a s C ommodity Charge G a s S u p p ly - AverageofNNGVentura,NBPLVenturaTransferPoint andNNGDemarcation first of month index gas p r ice $ 0 . 1 3 8 0 0 F u e l U s e – 0 . 6 4 % N N G , 1 . 5 3 % N B P L a n d 1 . 7 1 % C o mpany L&U 0.00330 P ipeline Transportation Fee 0 . 0 0 3 7 6 S c h e d u ling Fee 0 . 0 0 1 3 8 T o tal G a s Component Charge $ 0 . 1 4 6 4 4 D a t e F i l e d : A p r i l 3 , 2 0 2 4 EffectiveDate:April2,2024 Issuedby: Jeff Decker, Specialist Regulatory SOUTH DAKOTA GAS RATE SCHEDULE NORTHWESTERN ENERGY PUBLIC SERVICE CORPORATION d/b/a NORTHWESTERN ENERGY SIOUX FALLS SectionNo.3 SOUTHDAKOTA 353rdRevised SheetNo.9b Canceling 352ndRevised Sheet No. 9b ADJUSTMENT C L A U S E R A T E S ( C o n t, i n u e d ) P e r T h e r m Delivered Cost o f E n e r g y ( Continued): P e r Month Rate No. 85 - Commercial and Industrial-Interruptible Sales Service Gas Commodity Charge G a s S u p p ly - AverageofNNGVentura,NBPLVenturaTransferPoint andNNGDemarcation first of month index gas price 0.13800 F u e l U s e - 0 . 6 4 % N N G , 1 . 5 3 % N B P L a n d 1 . 7 1 % C o mpany L&U 0.00330 P ipeline Transportation Fee 0 . 0 0 3 7 6 R e leased Capacity Surcharge 0 . 0 1 4 0 0 B a lancing Services 0 . 0 0 3 0 0 S c h e d u ling Fee 0 . 0 0 1 3 8 T o tal G a s Component Charge $ 0 . 1 6 3 4 4 Rate No. 86 – Gas Contract Sales Service Rate No. 86 Gas Commodity Charge – Group 1 $0.58220 Rate No. 86 Gas Commodity Charge – Group 2 $0.41400 Rate No. 86 Gas Commodity Charge – Group 3 $0.47450 Rate No. 86 Gas Commodity Charge – Group 4 $0.45110 Rate N o . 8 6 G a s I n d e x $ 0 . 1 4 6 4 4 Rate No. 87 - Gas Transportation Firm Supply Standby Service Gas Demand Charge, per therm of daily, contract demand Rate No. 84 supply standby costs $0.07 RateNo.84pipelinecapacitycosts 1.25 T o tal D e mand Charge $ 1 . 3 2 G a s C ommodity Charge Rate N o . 8 4 G a s Commodity Charge $ 0 . 1 4 6 4 4 Imbalance Cash-out Rate Index Points (Rate No. 84, 85, 86 and 87) Northern, Ventura 50%, Demarcation 50% Northern Border, Ventura\TP 100% less applicable fuel Ad Valorem Taxes Paid: Rate No. 81 - Residential Gas Service Commodity Charge $0.0045 Rate No. 82 - General Gas Service Commodity Charge $0.0029 Rate No. 84 – Comm. & Ind. – Firm Commodity Charge - Option A $0.0019 Commodity Charge - Option B $0.0012 Rate No. 85 – Comm. & Ind. - Interrupt Commodity Charge - Option A $0.0019 Commodity Charge - Option B $0.0012 Rate No. 86 – Contract Sales Service Commodity Charge - Option A $0.0019 Commodity Charge - Option B $0.0012 Rate No. 87 – Gas Transportation Service Commodity Charge - Option A $0.0019 Commodity Charge - Option B $0.0012 DateFiled:April3,2024 EffectiveDate

Very cold winters increase demand for natural gas and to a lesser extent, electricity, while warmer than normal summers increase demand for electricity, especially among our residential and commercial customers., Thus, the rates we are allowed to charge may or may not match our costs at any given time., Demand for electricity and natural gas is often greater in the summer and winter months associated with cooling and heating., Such technologies could also result in further declines in commodity prices or demand for delivered energy., Demand for our Montana transmission capacity fluctuates with regional demand, fuel prices and weather related conditions.

The changes in production, labor demand and intermediate demand caused by the changes that occur due to 111(d) cause these blocks of the economy to react and adjust to a new equilibrium., These transactions would occur on an exchange where prices would be set by supply and demand., The changes in production, labor demand and intermediate demand caused by the changes that occur due to 111(d) causes these blocks of the economy to react and adjust to a new equilibrium., With more than 10,000 fewer people living in Montana as a result of 111(d), demand for state and local government services is lower, The loss in the state’s share of the $16 million paid by the mine in Federal royalties, which is $8 million, is included in the category Current Charges shown in the table.

Monthly Charges: OptionAOptionB CustomerCharge p e r M e t e r : $ 1 5 0 . 0 0 $ 3 5 0 . 0 0 N o n - G a s C o m m o d i t y C h a r g e , a l l u s e , p e r t h e r m: $0.0662 $0.0335 DemandChargepertherm of daily contract demand as shown on Sheet 9a, as applicable to firm service customers, never less than 50 therms., Released Capacity and Balancing Services Surcharge: Foralltherms taken during a month in excess of the product of the daily contract demand times the number of days in the billing period an additional $0.0170 per therm shall be assessed and added to the Gas Commodity Charge shown on Sheet No. 9a., Minimum Monthly Bill: TheCustomer Charge plus the amount for therms of contract demand., All surcharge gas charges collected will be in addition to the regular Commodity Charge for such gas., All unauthorized gas in excess of Contract Demand so used shall be “Penalty Gas” and be paid by the Customer at a rate which is the greater of $3.00 per therm or the maximum penalty charges permitted to be made by the Company’s upstream service providers for takes of natural gas in excess of authorized limitations, in addition to the regular Commodity Charge for such gas.

The net of these two activities is charged (or credited) to NorthWestern., In general, the battery is connected to the VER resource that is used to charge the battery., • Demand response resources under automated control., Demand Side Management – The potential for reduction of consumer demand for energy through various methods such as fnancial incentives and behavioral change., Peak Demand – The highest hourly net energy consumption for load.

 SOUTH DAKOTA GAS RATE SCHEDULE NORTHWESTERN CORPORATION d/b/a NORTHWESTERN ENERGY Section No. 3 SIOUX FALLS 424thRevised SheetNo.9a SOUTH DAKOTA Canceling 423rdRevised SheetNo.9a ADJUSTMENTCLAUSERATES PerTherm Delivered Cost of Energy Per Month Rate No. 81 - Residential Gas Service Gas Commodity Charge $0.91318 Rate No. 82 - General Gas Service Gas Commodity Charge $0.91318 Rate No. 84 - Commercial and Industrial-Firm GasDemand Charge, per therm of daily contract demand (never less than 50 therms) NNG Pipeline Capacity Costs N N G R a t e / T h e r m 30.48%ofTF12Base $0.9737 $0.27 31.83%ofTF12Variable $1.1684 0.40 37.69%ofTF5 $1.9471 0.31 GRI Fee $0.0000 0.00 SBA Surcharge $0.0000 0.00 GSR Surcharge $0.0000 0.00 Order528Surcharge $0.0000 0.00 Stranded 858 Surcharge $0.0000 0.00 Total Pipeline Capacity Costs $ 0.98 NNG R e fund - 0 . 0 9 S u p p ly Standby 0.07 B a lancing Services 0.09 Total D e mand Charge $ 1 . 0 5 Theabovepercentages are based on the Company, ’s contract demand profile with NNG ( 4 9 , 0 2 0 MMBtu.), Rate Schedule MMBtu Demand Percentage T F 1 2 Base 13,705 2 7 . 9 6 % T F 1 2 V a r iable 1 6 , 8 4 1 3 4 . 3 6 % T F 5 1 8 , 4 7 4 ( 1 ) 3 7 . 6 9 % T o tals 4 9 , 0 2 0 1 0 0 . 0 0 % (1)Service is contracted for 5 months (15.70% is 5/12ths of 37.69%) G a s C ommodity Charge G a s S u p p ly - AverageofNNGVentura,NBPLVenturaTransferPoint andNNGDemarcation first of month index gas p r ice $ 0 . 5 5 9 6 0 F u e l U s e – 0 . 7 3 % N N G a n d 1 . 5 5 % C o mpany L&U 0.01480 P ipeline Transportation Fee 0 . 0 0 3 7 6 S c h e d u ling Fee 0 . 0 0 1 4 1 FebruaryColdWeatherEvent12monthrecovery 0.32000 T o tal G a s Component Charge $ 0 . 8 9 9 5 7 D a t e F iled: October 4, 2021 Effective Date: October 2, 2021 Jeffrey D e c k e r IssuedBy:RegulatoryDepartment SOUTH DAKOTA GAS RATE SCHEDULE NORTHWESTERN CORPORATION d/b/a NORTHWESTERN ENERGY Section No. 3 SIOUX FALLS 323rdRevised SheetNo.9b SOUTHDAKOTA Canceling 322ndRevised SheetNo.9b ADJUSTMENT C L A U S E R A T E S ( C, o n t i n u e d ) P e r T h e r m Delivered Cost o f E n e r g y ( Continued): P e r Month Rate No. 85 - Commercial and Industrial-Interruptible Sales Service Gas Commodity Charge G a s S u p p ly - AverageofNNGVentura,NBPLVenturaTransferPoint andNNGDemarcation first of month index gas price 0.55960 F u e l U s e - 0 . 7 3 % N N G a n d 1 . 5 5 % C o mpany L&U 0.01480 P ipeline Transportation Fee 0 . 0 0 3 7 6 R e leased Capacity Surcharge 0 . 0 1 4 0 0 B a lancing Services 0 . 0 0 3 0 0 S c h e d u ling Fee 0 . 0 0 1 4 1 T o tal G a s Component Charge $ 0 . 5 9 6 5 7 Rate No. 86 – Gas Contract Sales Service Rate No. 86 Gas Commodity Charge – Group 1 $0.57587 Rate No. 86 Gas Commodity Charge – Group 2 $0.57587 Rate No. 86 Gas Commodity Charge – Group 3 $0.57587 Rate N o . 8 6 G a s I n d e x $ 0 . 8 9 5 8 7 Rate No. 87 - Gas Transportation Firm Supply Standby Service Gas Demand Charge, per therm of daily contract demand Rate No. 84 supply standby costs $0.07 RateNo, .84pipelinecapacitycosts 0.98 T o tal D e mand Charge $ 1 . 0 5 G a s C ommodity Charge Rate N o . 8 4 G a s Commodity Charge $ 0 . 5 7 9 5 7 Imbalance Cash-out Rate Index Points (Rate No. 84, 85, 86 and 87) Northern, Ventura 50%, Demarcation 50% Northern Border, Ventura\TP 100% less applicable fuel Ad Valorem Taxes Paid: Rate No. 81 - Residential Gas Service Commodity Charge $0.0053 Rate No. 82 - General Gas Service Commodity Charge $0.0034 Rate No. 84 – Comm. & Ind. – Firm Commodity Charge - Option A $0.0022 Commodity Charge - Option B $0.0014 Rate No. 85 – Comm. & Ind. - Interrupt Commodity Charge - Option A $0.0022 Commodity Charge - Option B $0.0014 Rate No. 86 – Contract Sales Service Commodity Charge - Option A $0.0022 Commodity Charge - Option B $0.0014 Rate No. 87 – Gas Transportation Service Commodity Charge - Option A $0.0022 Commodity Charge - Option B $0.0014 DateFiled: October 4, 2021 Effective Date: October2,2021 Jeffrey D e c k e r IssuedBy:RegulatoryDepartment

In column (k), provide revenues from demand charges related to the billing demand reported in column (h)., In column (k), provide revenues from demand charges related to the billing demand reported in column (h)., In column (k), provide revenues from demand charges related to the billing demand reported in column (h)., In column (k), provide revenues from demand charges related to the billing demand reported in column (h)., In column (k), provide revenues from demand charges related to the billing demand reported in column (h).

Environmental Protection Agency (EPA) - A Federal agency charged with protecting the environment., The demand for natural gas largely depends upon weather conditions., Thus, the rates we are allowed to charge may or may not match our costs at any given time., Demand for our Montana transmission capacity fluctuates with regional demand, fuel prices and weather related conditions., This charge is recorded within other income, net on the Consolidated Statements of Income.

The Northwest Public Power Association briefed NEEL on results of a survey that indicate large numbers of utilities are considering rate structure changes, including shifts to higher fixed charges., The difference between “load” and “demand” is transmission and distribution losses between point of generation and point of demand., The Regional Emerging Technology Advisory Committee is now charged with optimizing regional investment in emerging energy-efficient technologies., The Council formed a demand response advisory committee (DRAC) in August 2016 that has assisted the Council in several key areas; namely: defining demand response, providing data on planned and existing demand response programs, and highlighting key barriers to demand response implementation., KEY BARRIERS TO DEMAND RESPONSE IMPLEMENTATION The DRAC has spent significant time discussing the barriers to demand response.

SYSTEM FA C T S ELECTRIC OPERATIONS 4 Service Area Size 97,540 square miles (two-thirds of Montana) Peak & Average Load The total control area peak demand was approximately 1,909 megawatts (MWs) on July 27, 2021., Our control area average demand for 2021 was approximately 1,321 MWs per hour for the year on average, with total energy delivered of more than 11.57 million MWhs, for year ended December 31, 2021., Montana customers fund energy effciency as a least-cost resource in supply rates and through the Universal System Benefts Charge (USBC)., In 2007, Montana passed new laws curtailing the ability for consumers under 5 MW peak demand to purchase electricity from alternative suppliers., T h e u t i l i t y b u y s a s i g n i f c a n t p o r t i o n o f g a s f rom independent producers in the warmer months and stores it in storage felds across Montana to help keep the price stable and affordable. 59% Carbon-Free MONTANA 2021 ELECTRIC GENERATION PORTFOLIO BASED ON MWH OF OWNED AND LONG-TERM CONTRACTED RESOURCES Wind Owned 2.4% Wind Contracted 21.1% Hydro Owned 33.1% Hydro Contracted 1.5% Solar Contracted 0.5% Coal Owned 23.0% Contracted CELP & YELP 12.3% Natural Gas/Other Owned 4.2% Natural Gas Contracted 1.9% RAT E S NORTHWESTERN ENERGY’S JANUARY 1, 2022 ELECTRIC COSTS BY SIZE & CUSTOMER TYPE1 Residential Commercial Industrial GS1 Secondary Non Demand GS1 Secondary Demand GS1 Primary Demand GS2 Substation Demand Monthly kWh 750 1,500 14,000 180,000 650,000 Peak Monthly kW Demand N/A N/A 40 500 1,000 TOTAL ELECTRIC COSTS (supply, distribution, transmission & other charges) Monthly Cost $88.21 $189 $1,483 $17,488 $47,488 Average

Navigant estimated the amount of NEM solar that will be installed at NorthWestern distribution feeders based on (1) the number of customers receiving service under NorthWestern’s residential and general service rate classes (i.e., primary demand, primary non-demand, secondary demand, and secondary non- demand) at each substation, (2) an analysis of solar production’s coincidence with substation-level peak, and (3) seasonality., Navigant obtained substation capacity ratings and compared these ratings to seasonal peak demands projected at each substation; NorthWestern provided demand forecast projections for each substation., The team applied current rates for each of NorthWestern’s bill categories (i.e., supply energy, supply deferred costs, distribution energy, CTC-QF, USBC, transmission demand, and distribution demand) as applicable to customers with solar PV up to 50 kW, split by customer class (i.e., residential, general secondary demand, general secondary non-demand, general primary demand, and general primary non-demand)., This model incorporates the same generation base, demand forecasts, fuel prices, other operating costs, and plant parameters that are utilized throughout the market simulation modeling process., Navigant applies its own analysis to provide macroeconomic outlook and natural gas supply and demand data for the model, including infrastructure additions and configurations, and its own supply and demand elasticity assumptions.

Demand Side Management: Energy Effciency and Demand Response......................................... 34 5.2., Demand side management measures like energy effciency and demand response will also contribute to reducing the shortfall, though they will not be adequate on their own given the magnitude of NorthWestern’s c a p a c i t y d e f c i t ., In their planning assessments, the California Independent System Operator (CAISO) assumed they would be able to import over 10 GW of power to meet their peak demand., The forecast includes the expected reduction in peak loads resulting from the benefts of demand side management measures., This increases the complexity of ensuring an adequate supply of power for meeting customers’ demand when it peaks and requires careful assessment of the likely level of generation that will be provided by weather-driven resources during periods of peak demand, which often occur during extreme weather events.

The battery system uses advanced lead acid technology and is designed for 180 kWh of storage with 2,000 charge/discharge cycles at 50% depth of discharge/cycle.,  Examine and quantify the value streams of this form of distributed energy storage, including feeder support, reduced line loss, potential for transmission and distribution infrastructure upgrade deferral, passive demand response, energy efficiency, or other location-specific energy management solutions, The Demand Shifter can potentially complement renewable generation sources, contribute to spinning reserves, reduce capital costs, and help avoid dispatching more costly incremental energy generation sources, especially during peak pricing periods.

 NorthWestern Corporation, dba NorthWestern Energy Schedule O‐3 South Dakota Electric Page 1 of 2 Test Year Ended December 31, 2022 Derivation of Increased Rates and Proof of Revenue Billing Billing Line Description Units Rate Units Rate Revenue $ % 1 2 3 Interruptible Irrigation Service Rate 16 Calculated per Book Calculated 4 Customer Charge 16O (May‐Oct) 425 $45.00 $19,125 425 $55.00 $23,375 $4,250 22.22% 5 Customer Charge 16OW (May‐Oct) 2 $22.50 45 2 $55.00 110 65 144.44% 6 Customer Charge 16O (Nov‐Apr) 5 $45.00 225 5 $25.00 125 ‐100 ‐44.44% 7 Customer Charge 16OW (Nov‐Apr) 385 $22.50 8,663 385 $25.00 9,625 963 11.11% 8 Off‐Peak Energy Charge (May‐Oct) 1,736,881 $0.02437 42,328 1,736,881 $0.03157 54,833 12,506 29.54% 9 Off‐Peak Energy Charge (Nov‐Apr) 57,966 $0.02437 1,413 57,966 $0.03157 1,830 417 29.54% 10 On‐Peak Energy Charge (May‐Oct) 190,672 $0.13130 25,035 190,672 $0.16885 32,195 7,160 28.60% 11 On‐Peak Energy Charge (Nov‐Apr) 7,644 $0.13130 1,004 7,644 $0.16885, 1,291 287 28.60% 12 Shoulder Period Energy Charge (May‐Oct) 619,322 $0.05664 35,078 619,322 $0.07284 45,111 10,033 28.60% 13 Shoulder Period Energy Charge (Nov‐Apr) 32,812 $0.05664 1,858 32,812 $0.07284 2,390 532 28.60% 14 Demand Charge per Season 238 $130.81 31,195 238 $168.22 40,116 8,921 28.60% 15 Minimum Customer Charge per Season 0.000 $270.00 0.000 $330.00 0 0.00% 16 Irrigation Season kWh On Peak 198,316 $152,806 198,316 195,741 42,935 28.10% 17 Non‐Irrigation Season kWh Off & Shoulder 2,446,981 13,162 2,446,981 15,261 2,098 15.94% 18 Annual Total 2,645,297 $165,969 $166,326 2,645,297 $211,002 $45,033 27.13% 19 Book to Bill Revenue Ratio 100.215% 100.000% 20 Proposed Base Rate Revenue $211,002 $44,676 26.86% Revenue Change Revenue ‐‐‐‐‐‐‐‐‐‐ Present Rates ‐‐‐‐‐‐‐‐‐‐ ‐‐‐‐‐‐‐‐‐‐ Proposed Rates ‐‐‐‐‐‐‐‐‐‐ NorthWestern Corporation, dba NorthWestern Energy Schedule O‐3 South Dakota Electric Page 2 of 2 Test Year Ended December 31, 2022 Derivation of Increased Rates and, Proof of Revenue Billing Billing Line Description Units Rate Units Rate Revenue $ % 1 1 2 Irrigation Service Rate 17 Calculated per Book Calculated 3 Power Factor Charge (May‐Sept) $2,705 $3,459 $754 27.87% 4 Power Factor Charge (Oct‐Apr) 1,118 $1,430 312 27.91% 5 Demand Charge per HP (May‐Sept) 2,800 $4.870 13,636 2,800 $5.980 16,744 3,108 22.79% 6 Demand Charge per HP (Oct‐Apr) 590 $4.870 2,873 590 $5.980 3,528 655 22.79% 7 Energy Charge (May‐Sept) 308,327 $0.04960 15,293 308,327 $0.06029 18,589 3,296 21.55% 8 Energy Charge (Oct‐Apr) 50,284 $0.04960 2,494 50,284 $0.06029 3,032 538 21.55% 9 Total Irrigation Season (May‐Sept) 308,327 $31,634 308,327 $38,792 $7,158 22.63% 10 Total Non‐Irrigation Season (Oct‐Apr) 50,284 6,485 50,284 7,990 $1,504 23.20% 11 Annual Total 358,611 $38,119 $38,176 358,611 $46,782 $8,662 22.72% 12 Book to Billed Revenue Ratio 100.1% 100.000% 13 Proposed Base Rate Revenue $46,782 $8,606 22.54% Revenue Change Revenue ‐‐‐‐‐‐‐‐‐‐ Present Rates ‐‐

Analytical Approach  Resources Considered  ELCC Results (Summary)  ELCC Results (Details)  Utilization of Results  Appendix Background 4 Project Background  NorthWestern Energy hired E3 to analyze the capacity value (ELCC) of additional renewable energy, energy storage, and hybrid resources • NWE’s current capacity shortfall is ~650 MW identified in their 2019 Electricity Supply Resource Procurement Plan • Results from E3’s ELCC modeling to be used to inform the analysis of bids in NWE’s all-source capacity RFP – RFP seeks 280 MW of effective capacity to partially fill NWE’s identified capacity shortfall NWE-identified Capacity Need Source: 2019 Electric Supply Resource Procurement Plan Analytical Approach 6 This Study Utilizes E3’s Renewable Energy Capacity Planning (RECAP) Model  Resource adequacy is a critical concern under high renewable and decarbonized systems • Renewable energy availability depends on the weather • Storage and Demand, from solar or wind, limiting its ability to fully charge during periods of low renewable output • No RE charging constraint means storage can charge from the grid Te c hnology Renewable Capacity / Interconnection Limit (MW-AC) Battery Capacity (MW-AC) Battery Duration RE Charging Constraints AC or DC Coupled ILR Solar 100 MW 100 MW 4 hours No DC 1.7 Solar 100 MW 100 MW 4 hours Yes DC 1.7 Solar 100 MW 50 MW 4 hours No AC 1.3 Solar 100 MW 25 MW 4 hours No AC 1.3 Wind 100 MW 50 MW 4 hours No n/a n/a Wind 100 MW 50 MW 4 hours Yes n/a n/a Wind 100 MW 25 MW 4 hours No n/a n/a 15 Hybrid Solar – Coupling Method  AC-Coupled • Pros: – Easy to retrofit, more operational flexibility • Cons: – Higher inverter losses  DC-Coupled • Pros: – Cheaper – Lower losses – Might be able to obtain the solar energy that will otherwise be clipped • Cons: – PV Generation + Battery discharge constrained by the shared inverter *Diagram source: https://blog.fluenceenergy.com, Gross Load Net Load After Storage Charge Discharge Loss of Load Available Dispatchable Resources • Coal • Gas • Nuclear • Geothermal • Demand Response Illustrative example 41 Hybrid Re s ources: Ke y Va riables  Key variables for modeling hybrid resources in RECAP Variable Options Recommended Scenario(s) Renewable Te c hnology Wind or solar Wind and Solar VER to Storage Ratio Solar: typically ~3:1 to 1:1 Wind: typically ~10:1 to 4:1 Solar: 4:1, 2:1, 1:1* Wind: 4:1, 2:1 Storage Duration Solar: typically 1-4 hours Wind: typically 1-2 hours Solar: 4 hours Wind: 4 hours** Shared Inverter Solar: A C or DC coupled AC and DC coupled scenarios ITC Charging Limits Charge from VER or can charge from grid Can charge from grid + RE charging sensitivity Inverter Loading Ratio Solar: 1.3 to 1.7 1.7 for DC-coupled, 1.3 for A C-coupled * While a 1:1 ratio with a high ILR is becoming more common in solar saturated grids like Hawaii and the Southwest, it is less, likely to be economic in higher latitudes like MT with more limited solar to charge batteries during many parts of the year. ** While most existing wind hybrids have lower duration, E3 recommends 4 hours, which will maximize RA value and is the duration for the MT Caithness Beaver Creek project (320 MW wind, 160 MW / 640 MWh storage). *** NOTE: charging from the grid does not necessarily revoke the ITC., If not grid charging constraints, stand-alone ELCCs can be used, subject to inverter limits if DC coupled solar. 42  Hybrid resources should have equal or lower ELCCs to stand alone resources for similar capacity + storage duration  Charging constraints (e.g. requiring the storage to charge from renewables for the solar ITC) likely to further reduce hybrid ELCCs Hybrid vs.

The supply portion of the bill for natural gas is subject to twice yearly fuel cost adjustments and is shown separately from the delivery charge., ELECTRIC OPERATIONS - SOUTH DAKOTA Service Area Size 25 counties in eastern South Dakota Peak & Average Load Peak demand was approximately 344 MWs, the average daily load was approximately 200 MWs, and 1.68 million megawatt hours were supplied to customers during 2021., The chart to the right shows these various billing components for a NorthWestern Energy commercial customer with a monthly usage of 14,000 kWh and 40 kW demand., RAT E S 4 4 % C a r b o n - F r e e S O U T H D A K O TA 2 0 2 1 E L E C T R I C G E N E R AT I O N P O RTFOLIO BASED ON MWH OF OWNED AND LONG-TERM CONTRACTED RESOURCES Wind Owned 20.4% Wind Contracted 23.4% Coal Owned 52.2% Natural Gas/Other Owned 4.0% SOUTH DAKOTA NORTHWESTERN ENERGY COMMERCIAL CUSTOMER MONTHLY ELECTRIC BILLING COMPONENTS JANUARY 1, 2022 USING 14,000 KWH & 40 KW DEMAND PER MONTH Demand 33% Energy Supply 43% Fuel and Purchased Power 20% Power Factor (85%) 4% RAT E S NORTHWESTERN ENERGY’S JANUARY 1, 2022 ELECTRIC COSTS BY SIZE & CUSTOMER TYPE1 Residential Commercial and Industrial Rate 21 Rate 33 Rate 34 Rate 34 Monthly kWh 750 1,500 14,000 180,000 650,000 Peak Monthly kW Demand N/A 0 40 500 1,000 ACTUAL MONTHLY E L E C T R I C B I L L J A N U A RY 1, 2022 Average Monthly Cost per kWh for Supply and Delivery $ 0.138 $ 0.146 $ 0.121 $ 0.095 $ 0.068 Average Monthly Cost $ 103.78 $ 219 $ 1,689 $ 17,181 $ 44,397 1 Rates effective January, SOUTH DAKOTA NORTHWESTERN ENERGY COMMERCIAL CUSTOMER MONTHLY NATURAL GAS BILLING COMPONENTS JANUARY 1, 2022 USING 200 THERMS PER MONTH NEBRASKA NORTHWESTERN ENERGY COMMERCIAL CUSTOMER MONTHLY NATURAL GAS BILLING COMPONENTS JANUARY 1, 2022 USING 200 THERMS PER MONTH Monthly Service Charge 5% Monthly Service Charge 4% Delivery Charge (with 2% MGP Refund Included) 15% Delivery Charge 12% Purchased Gas Commodity 80% Purchased Gas Commodity 84% NORTHWESTERN ENERGY’S JANUARY 1, 2022 ELECTRIC COSTS BY SIZE & CUSTOMER TYPE1 Residential Commercial and Industrial Rate 21 Rate 33 Rate 34 Rate 34 Monthly kWh 750 1,500 14,000 180,000 650,000 Peak Monthly kW Demand N/A 0 40 500 1,000 ACTUAL MONTHLY E L E C T R I C B I L L J A N U A RY 1, 2022 Average Monthly Cost per kWh for Supply and Delivery $ 0.138 $ 0.146 $ 0.121 $ 0.095 $ 0.068 Average Monthly Cost $ 103.78 $ 219 $ 1,689 $ 17,181 $ 44,397 1 Rates effective January 1, 2022; fuel and purchase power portion of

Demand charges, if applicable, will be billed in the month that billable demand units are established. 4., Demand charges will be billed in full for each month during the irrigation season after the commencement of energy usage., Minimum C h a r g e Theminimum monthly bill will be the demand charge for 5 kilowatt plus actual energy charges., Maximum Charge Themaximum monthly charge shall be the higher of (1) the minimum charge or (2) the combined average cost of $ 0.23 per kilowatt hour for demand and energy charges., The monthly standby demand charge will be based on the trailing 12 month peak demand at the time of execution of the contract.

Monthly Charges: Opti o n A O p t i o n B C u s t o m e r C h a r g e p e r M e t e r : $100.00 $300.00 Non-GasCommodityCharge, all use, per therm: $0.0662 $0.0335 DemandChargepertherm of daily firm demand as shown on Sheet 9a., Gas Demand Payment Elections A., Minimum Monthly Bill: The Customer Charge plus the amount for therms of firm demand (never less than 50 therms)., PenaltyProvision If customer fails to comply with Company’s request to curtail or in any way fails to limit the use of gas to the volume of Daily Demand , then all unauthorized gas in excess of Daily Demand so used shall be “Penalty Gas” and be paid by the Customer at a rate which is the greater of $3.00 per therm or the maximum penalty charges permitted to be made by the Company’s upstream service providers for takes of natural gas in excess of authorized limitations, in addition to the regular Commodity Charge for such gas., All surcharge gas charges collected will be in addition to the regular Commodity Charge for such gas.

Information for our seasonal irrigation service customers about energy consumption and tips to minimize consumption.

CHARGE SIZE PER THERM CLEAN-UP CLAUSE RATE Adjustment Refund PGC customer chg 81 $8.00 FIRST 30 $0.37880 $0.00000 0.00450 $0.38330 $0.00000 -$0.04290 0.58811 $0.92851 OVER 30 $0.17000 $0.00000 0.00450 $0.17450 $0.00000 -$0.04290 0.58811 $0.71971 82 $10.00 FIRST 400 $0.17280 $0.00000 0.00290 $0.17570 $0.00000 -$0.01740 0.58811 $0.7464 NEXT 1,600 $0.11000 $0.00000 0.00290 $0.11290 $0.00000 -$0.01740 0.58811 $0.6836 OVER 2,000 $0.08650 $0.00000 0.00290 $0.08940 $0.00000 -$0.01740 0.58811 $0.6601 84A $100.00 ALL Therms $0.06620 $0.00000 0.00190 $0.06810 $0.00000 -$0.01560 0.14644 $0.1989 84ALG $100.00 ALL Therms $0.06620 0.00190 $0.06810 0.14644 $0.2145 Supplmnt Gas 2 Tab for rates 84A and 84ALG - "Daily Demand Rate 1" $1.23000 84B $300.00 ALL Therms $0.03350 $0.00000 0.00120 $0.03470 $0.00000 -$0.00210 0.14644 $0.1790 84BE8 Supplmnt Gas 2 Tab for rates 84B and 84BE8 - "Daily Demand Rate 1" $1.23000 85A $100.00 ALL Therms $0.06620 $0.00000 0.00190 $0.06810 $0.00000, 0.00120 $0.03470 -$0.00210 $0.0326 87BOR 350.00 ALL Therms $0.03350 $0.00000 0.00120 $0.03470 -$0.00210 $0.0326 87BSP 350.00 ALL Therms $0.03350 $0.00000 0.00120 $0.03470 -$0.00210 $0.0326 87BVQ 350.00 ALL Therms $0.03350 $0.00000 0.00120 $0.03470 -$0.00210 $0.0326 87CHG $350.00 ALL Therms $0.03350 $0.00000 0.00120 $0.03470 -$0.00210 $0.0326 87CNL $350.00 ALL Therms $0.03350 $0.00000 0.00120 $0.03470 -$0.00210 $0.0326 "Billing Control Files" "Rate Adjustment Type Master" updates PGA01 Purch Gas Commodity SD 81 $0.588110 PGA02 Purch Gas Commodity SD 82 $0.588110 PGA03 Purch Gas Commodity SD 84 $0.146440 PGA04 Purch Gas Commodity SD 85 $0.163440 PGA05 Purch Gas Commodity SD 87 $0.146440 PGA20 Purch Gas Commodity SD 86 Index $0.146440 PGA21 Purch Gas Commodity SD 86 Offer 1 $0.582200 PGA22 Purch Gas Commodity SD 86 Offer 2 $0.414000 PGA23 Purch Gas Commodity SD 86 Offer 3 $0.474500 PGA24 Purch Gas Commodity SD 86 Offer 4 $0.451100 PGD01 Purchase Gas Demand, SD 84 1.2300000 PGD03 Purchase Gas Demand SD 87BOR 0.8000000 PGD04 Purchase Gas Demand SD 87BVQ 0.9102000 PGD05 Purchase Gas Demand SD 87BSP 1.0606000 PGD06 Purchase Gas Demand SD 87CNL 1.0163000 MGP81 Manufactured Gas Plant Adjustment -0.0429000 MGP82 Manufactured Gas Plant Adjustment -0.0174000 MGP8A Manufactured Gas Plant Adjustment -0.0156000 MGP8B Manufactured Gas Plant Adjustment -0.0021000 Average price of gas per therm based on 150 therms = $0.81 Contract Demand